Developing Marginal Near-Tight Gas Fields in a Mature Area With Long-Reach Hydraulically Fractured Wells - A Case Study
- P. Weijermans (ENGIE E&P Nederland B.V.) | G. Daniau (ENGIE E&P Nederland B.V.) | D. Westerhof (ENGIE E&P Nederland B.V.)
- Document ID
- Society of Petroleum Engineers
- SPE Europec featured at 78th EAGE Conference and Exhibition, 30 May-2 June, Vienna, Austria
- Publication Date
- Document Type
- Conference Paper
- 2016. Society of Petroleum Engineers
- 5 Reservoir Desciption & Dynamics, 5.5 Reservoir Simulation, 4.5 Offshore Facilities and Subsea Systems, 3 Production and Well Operations, 2.4 Hydraulic Fracturing, 5.8 Unconventional and Complex Reservoirs, 2.2 Installation and Completion Operations, 2.5.2 Fracturing Materials (Fluids, Proppant), 1.10.1 Drill string components and drilling tools (tubulars, jars, subs, stabilisers, reamers, etc), 4.1 Processing Systems and Design, 4.5 Offshore Facilities and Subsea Systems, 2.2.2 Perforating, 5.8.1 Tight Gas, 4.1.2 Separation and Treating, 1.10 Drilling Equipment, 2.1.3 Completion Equipment, 2 Well completion, 3 Production and Well Operations, 4 Facilities Design, Construction and Operation, 1.6 Drilling Operations
- hydraulic fracture stimulation, compartmentalised reservoirs, Southern North Sea, tight gas, marginal fields
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- 104 since 2007
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The L12/L15 area is located in the Dutch sector of the Southern North Sea, some 5–10 km from the coastline of the Wadden Islands. Exploration in the 1970s led to the discovery of five small, near-tight (permeability ~1 mD) gas accumulations in a Rotliegend sandstone reservoir, located at a depth of ~3000m. Two of the fields were developed in the 1990s with 5 production wells drilled from a central 9-slot processing platform. The three remaining discoveries, all within drilling reach of the platform, were considered too small, marginal and risky to develop. In 2009, it was decided to fully re-assess the area. This resulted in successful development of two of the undeveloped discoveries in the past five years. Both fields have been drilled with a single long-reach well (>4 km step-out), stimulated with a massive hydraulic fracture from a stimulation vessel. Similar development of the third accumulation is being prepared.
An integrated approach was key to the success of the developments. For both fields, detailed static and dynamic reservoir modeling was performed to select the optimum well location and estimate potential recovery. Optimising the stimulation treatments involved hydraulic fracture modeling and defining a suitable completion, perforation and clean-up strategy. Extensive post-job analysis of the hydraulic fracture treatments was performed, integrating core data, wireline log data, fracture treatment data, welltest data and production data. Results of the analysis clearly show the value of hydraulic fracturing in these marginal near-tight gas fields.
The first well showed a post-frac well performance which exceeded expectations, while in the second well the fracture performance was below expectation after initial clean-up, although well productivity improved during the first weeks of production, which was attributed to continued clean-up of the formation from frac fluids. One of the fields discussed in the underlying paper illustrates the typical challenges associated with compartmentalised reservoirs in the Rotliegend play in the Southern North Sea. This field has a Northern compartment which is depleted from an initial pressure of 340 bar to a pressure of less than 100 bar after more than 15 years of production. The Southern compartment of the field was known to form a separate accumulation (within the same structural closure) with a deeper GWC and different gas composition compared to the Northern compartment, based on data from an appraisal well drilled in 1982. The new development well targeting this field was drilled in a compartment located between the Northern and Southern compartment, with an unknown GWC. The well found the same (deep) GWC and gas composition as the 1982 appraisal well in the South, but nevertheless found the reservoir to be depleted by up to 50 bar which is attributed to direct communication with the Northern compartment. The case illustrates the complexities involved in compartmentalisation over geologic vs. production times.
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